This application claims the benefit under 35 U.S.C. § 119(e) of and is a continuation-in-part of U.S. Provisional Application Ser. No. 60/594,628, entitled “Zonal Isolation Tool,” filed Apr. 25, 2005; and of U.S. application Ser. No. 11/308,617, entitled, “Zonal Isolation Tools and Methods of Use,” filed Apr. 12, 2006, both hereby incorporated by reference.
A zonal isolation tool should provide reliable, long-term isolation between two or more subsurface zones in a well. A typical application would be to segregate two zones in an open-hole region of a well, the zones being separated by a layer of low permeability shale in which the zonal isolation tool is placed. A nominal size configuration would be usable in wellbores drilled with an 8½ inch (21.6 cm) outer diameter bit below 9⅝ inch (24.5 cm) casing, but the use of zonal isolation tools is not limited to any particular size, or to use in open holes. By segregating open-hole intervals, downhole chokes may be used for production management. Similarly, selective zonal injection may be performed. If distributed temperature sensing is placed in the well, monitoring predictive control is possible.
A conventional completion assembly 10 with a zonal isolation tool 12 is illustrated in FIGS. 1 and 2 for allowing production of two separate flows 4A and 4B from an open hole 3. Assembly 10 may include a production packer 14, a gravel pack packer 16, flow control valves 18, and other components commonly used in downhole completions. Zonal isolation tool 12 may comprise a packer 20, a pair of anchors 22, a pair of polished bore receptacles (PBRs) 24, and an expansion joint 26. Service tools may include a setting string 28 and an isolation string 30.
However, most of the current openhole zonal isolation systems are not designed to enable long term, openhole, hydraulic isolation. Specific challenges include sealing and anchoring the system, and the ability to allow for expansion and/or contraction due to thermal effects, all located within the openhole interval of a sandface completion. There are also issues of coping with retaining the differential pressure rating for wider open hole internal diameters or changes in the open hole internal diameter within the specified operating envelope.
Therefore, while there have been some improvements in zonal isolation tool designs and systems, further improvement is desired.
In general, a zonal isolation system for use in a well is provided. The zonal isolation system includes a zonal isolation tool, at least one anchor, and at least one polished bore receptacle. The zonal isolation system includes a setting string for activation of the zonal isolation tool and/or the at least one anchor. The zonal isolation system may also include an isolation string for maintaining separation zones during production or injection of the well.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic side elevation view, partially in longitudinal cross section, of a completion assembly comprising an embodiment of a zonal isolation tool constructed in accordance with embodiments of the invention;
FIG. 2 is a schematic side elevation view, partially in longitudinal cross section, of the zonal isolation tool of FIG. 1, along with a setting string and isolation string;
FIG. 3 is a schematic longitudinal side elevation view of a portion of the base structure of the zonal isolation tool of FIG. 1;
FIG. 4 is a schematic longitudinal side elevation view of a portion of the base structure of the zonal isolation tool of FIG. 1 after inflation pressure has been applied;
FIG. 5 is a schematic longitudinal side elevation view of a portion of the base structure of the zonal isolation tool of FIG. 1 with a compressive load being applied;
FIGS. 6A-D are schematic longitudinal cross sectional views of a portion of the base structure of the zonal isolation tool of FIG. 1 illustrating an operational sequence;
FIG. 7 is a schematic longitudinal cross section view of a portion of the zonal isolation tool of FIG. 1 illustrating the seal element;
FIG. 8 is a schematic longitudinal cross section view of a portion of the zonal isolation tool of FIG. 1 illustrating the seal element after inflation pressure;
FIG. 9 is a schematic longitudinal cross section view of a portion of the zonal isolation tool of FIG. 1 illustrating the seal element after compressive loading is applied;
FIG. 10 is a more detailed schematic longitudinal cross section view of the seal element of the zonal isolation tool of FIG. 1;
FIG. 11 is an enlarged detailed view of a portion of the seal element of the zonal isolation tool of FIG. 1;
FIG. 12 is an enlarged schematic longitudinal cross section view illustrating anti-extrusion sheets used in the zonal isolation tool of FIG. 14;
FIG. 13 is a perspective schematic view of the structural undercarriage of the zonal isolation tool of FIG. 1;
FIGS. 14A and 14B are schematic axial cross section views illustrating alternate fluid pathways that may be incorporated in the zonal isolation tool of FIG. 1; and
FIGS. 15A, 15B, and 15C are schematic longitudinal cross section views of another embodiment of a zonal isolation tool.
FIG. 16 is a schematic side elevation views, partially in longitudinal cross section, of the zonal isolation system along with a setting string and isolation string;
FIG. 17 is a partial schematic side views of a slip anchor;
FIG. 18 is a partial schematic side views of a two-stage slip anchor;
FIG. 19 is a perspective view of a self locking anchor;
FIG. 20 is a partial schematic side views of a penetrator type anchor;
FIG. 21 is a schematic cross section side view of a portion of the zonal isolation system;
It is to be noted, however, that the appended drawings are not to scale and illustrate only some embodiments of this invention, and are therefore not to be considered limiting of its scope.
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
Described herein is a zonal isolation system 80 for use in wellbores. A “wellbore” may be any type of well, including, but not limited to, a producing well, a non-producing well, an experimental well, and exploratory well, and the like. Wellbores may be vertical, horizontal, any angle between vertical and horizontal, diverted or non-diverted, and combinations thereof, for example a vertical well with a non-vertical component. Also, in the description, the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via another element”. The term “set” is used to mean “one element” or “more than one element”. The terms “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, “upstream” and “downstream”, “above” and “below”, and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly described some embodiments as disclosed herein. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate.
Referring now to FIGS. 16 and 21, the open hole zonal isolation system 80 may comprise a zonal isolation tool 29, a first anchor 82 and a second anchor 84, an upper polished bore receptacle 86 and a lower polished bore receptacle 88, and an expansion joint 90. The zonal isolation system may also include a setting string 92 and an isolation string 94.
Referring now to FIGS. 3, 4 and 5, an embodiment of the zonal isolation tool 29 is disclosed. The drawings are schematic in fashion and not to scale. The same numerals are used to call out similar components. This embodiment includes an elastomeric seal member 34 initially inflated by a fluid entering an inflation port 21 in base pipe 15. Inflation port 21 aligns with a similar passage 31 in a member 19, which may be described as an inflation valve, during initial expansion of seal member 34. Member 19, along with a moveable piston 13 and a movable sleeve 7 also define an expandable chamber 2. Moveable sleeve 7 includes a through hole 9, whose function will become apparent. Base pipe 15 includes another through passage 11 opening into a chamber 23 formed in a stationary sleeve 5. Moveable piston 13 is able to slide longitudinally downward within stationary sleeve 5. Passage 31 opens into a large chamber 43 able to accept fluid to expand sealing member 34. Chamber 43 is sealed by an o-ring or other seal at 39.
FIGS. 4 and 5 illustrate operation of the zonal isolation tool 29. Sealing member 34 is initially expanded via fluid pressure entering through inflation port 21 and passage 31 and into chamber 43 to an initial expansion pressure, causing sealing member 34 to engage a wellbore or borehole wall 33. During this initial expansion, moveable piston 13 and moveable sleeve 7 remain essentially stationary. Once the defined initial pressure is reached in chamber 43, member 19 moves to the left, blanking or closing inflation port 21, and through hole 9 opens into the hydroforming chamber 43, as illustrated in FIG. 5. After inflation port 21 is blanked off or closed, a fluid 45 is introduced into chamber 23 via through hole 11, causing moveable piston 13 and moveable sleeve 7 to the right in FIG. 5. This in turn causes sealing member 34 to compress axially and also to form a seal at or near a leading edge 32. Fluid pressure 35A is also allowed to vent from the annulus 6 into chamber 43 through passage 9 and pressure 35B is nearly equal to pressure 35A, allowing pressure communication as indicated by the arrows from annulus 6 to chamber 43. Pressures 35A and 35B are higher than pressure 37. Sealing member 34 (FIG. 5) may include an underlying carriage 36 (FIG. 13). After actuation, differential pressure energizes the cup-type seal 34, vis-à-vis pressure in 35B which is greater than pressure in 37. It should be noted that the fluid pressure used to activate the sealing member 34 may be transmitted to the sealing member 34 and/or setting pistons 13 by various means. An embodiment receives the tubing pressure via a setting tool 28 fitted with sealing elements (o-rings, packing, or the like). When the sealing members 34 are situated in polished bores both above and below the zonal isolation tool 29 or packer system, a pressure chamber is formed that communicates with the packer element and setting pistons 13. Pressure is applied thru the setting tool 28 via the surface control equipment at the rig. Another embodiment utilizes the differential pressure between the hydrostatic pressure downhole and a trapped atmospheric chamber (not shown) integral to the packer device. To activate the packer, a setting tool is used to break the seal of the atmospheric trap chamber. Once freed, the pressure differential may be used to hydroform the element, and further to apply the compressive load as claimed. A similar embodiment may compliment or even replace the trapped atmospheric chamber with a pre-charged volume of nitrogen or other gas stored within the packer. The result is to create a large differential pressure at setting depth. Further embodiments may include activation by non pressurizing means, such as mechanical ratcheting via an electric-powered or hydraulic-powered downhole device, such as a tractor run on slickline, e-line, or coiled tubing.
The zonal isolation tool 29 of this embodiment uses hydroforming pressure as a first step to energize. Initial inflation will affect a long length of sealing contact, assuring good compliance to the open hole. After initial inflation, a compressive load is applied via linear piston 7 (FIG. 5) to ensure sealing point 32 near the leading end of the sealing element structure.
The following are operational considerations, occurring sequentially: (1) the tubing or base pipe 15 must be open to the sealing member; (2) the initial inflation must stop when a defined pressure within sealing member 34 is reached; (3) inflation port 21 must be assuredly blanked from tubing or base pipe 15; and (4) a vent must open between sealing member 34 and annulus 6. As illustrated in FIGS. 3-5, in certain embodiments a linear compressive load from a moveable piston opens a vent such as passage 9 in FIG. 5. The operational sequence must happen in the proper order. FIGS. 6A-D illustrate this order. For example, if vent 9 is opened prior to port 21 being blanked, then it would become impossible to blank port 21 because open communication would be established. To blank the port 21, an o-ring must un-seal, then re-seal under dynamic conditions. Despite that limitation, other combinations of this sequence may work in other embodiments, as disclosed herein.
Referring to FIG. 7, several circumferential bands 40 may be employed to prevent seal 34 from expanding radially while running in hole. FIG. 7 illustrates schematically a simplified seal 34 with bands 40. The right end 38 of seal 34 is fixed while the left end 44 is free to displace axially to the right. A ratchet ring 42 prevents axial movement to the left and thus helps seal 34 retain elastic (potential) energy. Setting pressure is applied inside seal 34 via the packer setting tool 28 (FIG. 2). Bands 40 break when a defined pressure is reached, allowing seal 34 to expand and contact the formation wall 33 (FIGS. 4, 5). Another embodiment of this feature may replace or complement the circumferential bands with a poppet valve.
As illustrated in FIG. 8, the seal centerline in this embodiment lies to the right of the contact centerline. This behavior is conditioned by machining a notch 46 at the left end of carriage 36 (FIG. 12).
A setting pressure of approximately 1,500 psi (about 10.3 megaPascals) is used to lengthen the contact length of seal 34 with the formation (FIG. 8). Finally, the setting pressure is increased to approximately 2,500 psi (about 17.2 megaPascals) to: (1) blank port 21 (i.e. isolate inside of sealing member 34 from tubing or base pipe 15 pressure); (2) vent sealing member 34 to annulus 6 through vent 9; and (3) axially compress the left end of sealing member 34 to bias sealing point 32. The cup effect makes each seal unidirectional, as illustrated in FIG. 9. When a bidirectional seal is desired, at least two seals are required facing opposite directions.
A venting port 60 (FIG. 10) may be placed on the low-pressure side 37 of sealing member 34 to eliminate any atmospheric trap that would be created between the inner sealing element 50 outer sealing element 52. Total seal length is indicated at 55, while slotted length is indicated at 56 if a slotted carriage is employed.
Carriage 36 is illustrated in FIG. 13 as a cylinder having one or more machined slots 58 in the axial direction. These slots may be used to create individual beams 57 around the cylinder. The left end of beams 57 may be notched as illustrated in detail in FIG. 12 to simulate a “simply supported” beam. The right end may not be notched; if it is not, the right end simulates a “cantilevered” beam. Carriage 36 may also be un-slotted, that is, a thin solid tube.
Inner sealing element 50 (FIG. 11), sometimes referred to as a bladder, may be an elastomeric cylinder bonded near the ends of carriage 36 to provide inflation capability to sealing member 34. Inner sealing element 50 allows sealing member 34 to deploy under internal pressure and to self-energize when differential pressure across packer 20 is present. Because inner sealing element 50 may be cold-bonded to metal at 51, a mechanically energized wedge 53 may be used to improve reliability. Inner sealing element 50 may have a thickness ranging from about 0.10 to about 0.20 inch (from about 0.25 to about 0.5 cm), and may comprise 80 durometer HNBR, although the invention is not so limited, as other materials discussed herein may be employed.
Outer sealing element 52 may be a rubber cylinder bonded to the ends of the carriage 36 to provide sealing against the formation. Outer sealing element 52 may have any thickness that provides appropriate tear and wear resistance during conveyance and good conformability to open-hole irregularities. Its thickness may range from about 0.30 to about 0.70 inch (from about 0.76 to about 1.78 cm) to. Outer seal element 52 may also comprise 80 durometer HNBR, and may comprise other materials as discussed herein.
Dashed circle “A” in FIG. 11 refers to a detailed view illustrated in FIG. 12. The use of notched beams in support carriage 36 helps control the axial location of the leading edge 32 of the contact point of sealing member 34 with the formation. By allowing some degree of enhanced freedom in radial movement in or near the notched end 46, the maximum deflection point (contact point with maximum sealing pressure) shifts to the left of the structure, as illustrated schematically in FIGS. 8 and 9. This improves the overall sealing performance of sealing elements 50 and 52 under differential pressure and contributes to the long-term reliability of the apparatus, particularly sealing member 34. Additionally, individual beams 57 able to expand radially may be more efficient than a continuous metallic cylinder in terms of pressure required to achieve a given expansion and in terms of conforming to irregular open hole geometries. Carriage 36 may be made of, for example, 4130/4140 steel.
Anti-extrusion sheets 54 (FIG. 12) are, in the embodiment illustrated, sheet metal cylinders located between carriage 36 and outer sealing element 52 and inner bladder 50 to prevent extrusion through the gaps formed as individual beams 57 in carriage 36 expand and separate. Anti-extrusion sheets 54 may be slotted or un-slotted, and may have any thickness suitable for the intended purpose, but will likely range in thickness from about 0.020 to about 0.050 inch (from about 0.051 to about 0.13 cm). Anti-extrusion sheets may comprise half-hardness low-carbon steel, and if used are welded at 59 to carriage 36 at each end. Un-slotted anti-extrusion sheets may allow removal of inner elastomeric element 50 and a buffer layer. A buffer layer of non-metallic material may be added between the innermost anti-extrusion sheet metal cylinder 54 and inner elastomeric element 50. A buffer layer may be used to prevent the sharp edges of the sheet metal cylinder from puncturing the relatively thin layer of elastomer used for inner elastomeric member 50. Suitable buffer layer materials include polyetheretherketone (PEEK), and may be have a thickness ranging from about 0.010 to about 0.030 inch (about 0.025 to about 0.076 cm).
FIGS. 14A and 14B illustrate schematic cross section views at a screen pipe (FIG. 14A) and a packer (FIG. 14B). FIG. 14A illustrates shunt tubes 62 for pumping gravel slurry or injection fluids through a zonal isolation tool, and illustrates that the outer circumference of the screen may have a different center 70 than the inner circumference 72. FIG. 14B illustrates alternate fluid pathways for pumping gravel slurry or injection fluids through a zonal isolation tool. Three pathways 64 illustrated between a screen base pipe 66 and a packer base pipe 15, along with three packer setting ports 68. Maintaining a sufficiently large inner diameter is desirable to achieving full functionality for such alternate fluid pathways. The design illustrated preserves an equivalent area from for transport tubes. It is possible to move the packer and screen base pipes onto different centers, which would ease the disruption in the flow transition.
FIGS. 15A, 15B, and 15C illustrate schematically an alternate embodiment of the invention 80. This embodiment differs from embodiment 29 illustrated in FIGS. 3-5 in operation. After initial seal pressure is reached in chamber 43 using fluid 41, a moveable block 76 is moved to the right by fluid pressure 45, and an O-ring 77 is caused to unseat into a small chamber 78. In the same movement, inflation port 21 is blanked close, and high pressure fluid in annulus 6 is allowed to pass through chamber 78 into chamber 43, causing the pressures 35A and 35B to become nearly equivalent. Since there is no passage in block 76 to align with inflation port 21 in base pipe 15, there is less chance in this embodiment that annulus pressure will pass through port 21, and port 21 is more easily blanked.
The outer elastomeric elements engage an adjacent surface of a well bore, casing, pipe, tubing, and the like. Other elastomeric layers between the inner and outer elastomeric members may be provided for additional flexibility and backup. A non-limiting example of an elastomeric element is rubber, but any elastomeric materials may be used. A separate membrane may be used with an elastomeric element if further wear and puncture resistance is desired. A separate membrane may be interleaved between elastomeric elements if the elastomeric material is insufficient for use alone. The elastomeric material of outer sealing elements should be of sufficient durometer for expandable contact with a well bore, casing, pipe or similar surface. In some embodiments the elastomeric material may be of sufficient elasticity to recover to a diameter smaller than that of the wellbore to facilitate removal therefrom. The elastomeric material should facilitate sealing of the well bore, casing, or pipe in the inflated state.
“Elastomer” as used herein is a generic term for substances emulating natural rubber in that they stretch under tension, have a high tensile strength, retract rapidly, and substantially recover their original dimensions (or even smaller in some embodiments). The term includes natural and man-made elastomers, and the elastomer may be a thermoplastic elastomer or a non-thermoplastic elastomer. The term includes blends (physical mixtures) of elastomers, as well as copolymers, terpolymers, and multi-polymers. Examples include ethylene-propylene-diene polymer (EPDM), various nitrile rubbers which are copolymers of butadiene and acrylonitrile such as Buna-N (also known as standard nitrile and NBR). By varying the acrylonitrile content, elastomers with improved oil/fuel swell or with improved low-temperature performance can be achieved. Specialty versions of carboxylated high-acrylonitrile butadiene copolymers (XNBR) provide improved abrasion resistance, and hydrogenated versions of these copolymers (HNBR) provide improve chemical and ozone resistance elastomers. Carboxylated HNBR is also known. Other useful rubbers include polyvinylchloride-nitrile butadiene (PVC-NBR) blends, chlorinated polyethylene (CM), chlorinated sulfonate polyethylene (CSM), aliphatic polyesters with chlorinated side chains such as epichlorohydrin homopolymer (CO), epichlorohydrin copolymer (ECO), and epichlorohydrin terpolymer (GECO), polyacrylate rubbers such as ethylene-acrylate copolymer (ACM), ethylene-acrylate terpolymers (AEM), EPR, elastomers of ethylene and propylene, sometimes with a third monomer, such as ethylene-propylene copolymer (EPM), ethylene vinyl acetate copolymers (EVM), fluorocarbon polymers (FKM), copolymers of poly(vinylidene fluoride) and hexafluoropropylene (VF2/HFP), terpolymers of poly(vinylidene fluoride), hexafluoropropylene, and tetrafluoroethylene (VF2/HFP/TFE), terpolymers of poly(vinylidene fluoride), polyvinyl methyl ether and tetrafluoroethylene (VF2/PVME/TFE), terpolymers of poly(vinylidene fluoride), hexafluoropropylene, and tetrafluoroethylene (VF2/HPF/TFE), terpolymers of poly(vinylidene fluoride), tetrafluoroethylene, and propylene (VF2/TFE/P), perfluoroelastomers such as tetrafluoroethylene perfluoroelastomers (FFKM), highly fluorinated elastomers (FEPM), butadiene rubber (BR), polychloroprene rubber (CR), polyisoprene rubber (IR), IM, polynorbornenes, polysulfide rubbers (OT and EOT), polyurethanes (AU) and (EU), silicone rubbers (MQ), vinyl silicone rubbers (VMQ), fluoromethyl silicone rubber (FMQ), fluorovinyl silicone rubbers (FVMQ), phenylmethyl silicone rubbers (PMQ), styrene-butadiene rubbers (SBR), copolymers of isobutylene and isoprene known as butyl rubbers (IIR), brominated copolymers of isobutylene and isoprene (BIIR) and chlorinated copolymers of isobutylene and isoprene (CIIR).
The expandable portions of the packers may include continuous strands of polymeric fibers cured within the matrix of the integral composite body comprising elastomeric elements. Strands of polymeric fibers may be bundled along a longitudinal axis of the expandable packer body parallel to longitudinal cuts in a laminar interior portion of the expandable body. This can facilitate expansion of the expandable portion of the composite body yet provide sufficient strength to prevent catastrophic failure of the expandable packer upon complete expansion.
The expandable portions of the tools may also contain a plurality of overlapping reinforcement members. These members may be constructed from any suitable material, for example high strength alloys, fiber-reinforced polymers and/or elastomers, nanofiber, nanoparticle, and nanotube reinforced polymers and/or elastomers, or the like, all in a manner known and disclosed in U.S. patent application Ser. No. 11/093390, filed on Mar. 30, 2005, entitled “Improved Inflatable Packers”, the entirety of which is incorporated by reference herein.
The zonal isolation tools may be constructed of a composite or a plurality of composites so as to provide flexibility. The expandable portions of the tools may be constructed out of an appropriate composite matrix material, with other portions constructed of a composite sufficient for use in a wellbore, but not necessarily requiring flexibility. The composite may be formed and laid by conventional means known in the art of composite fabrication. The composite may be constructed of a matrix or binder that surrounds a cluster of polymeric fibers. The matrix can comprise a thermosetting plastic polymer which hardens after fabrication resulting from heat. Other matrices are ceramic, carbon, and metals, but the invention is not so limited. The matrix can be made from materials with a very low flexural modulus close to rubber or higher, as required for well conditions. The composite body may have a much lower stiffness than that of a metallic body, yet provide strength and wear impervious to corrosive or damaging well conditions. The composite tool body may be designed to be changeable with respect to the type of composite, dimensions, number of cable and fibrous layers, and shapes for differing downhole environments.
It is understood that the zonal isolation tool may be any type of isolation or separation device suitable for use in an openhole environment. These include, but are not limited to, hydroform-compress-energize packer, swellable elastomer packer, inflatable ECP, or rubber-compression packer. Furthermore, it is understood that multiple zonal isolation tools may be positioned or oriented in any manner to generate uni-directional or bi-directional sealing.
Referring now to the zonal isolation system illustrated in FIGS. 16 and 21, as stated above, the open hole zonal isolation system 80 may comprise the zonal isolation tool 29, the first anchor 82, the second anchor 84, the upper polished bore receptacle 86, the lower polished bore receptacle 88, and the expansion joint 90. The zonal isolation system may also include the setting string 92 and the isolation string 94. The zonal isolation system 80 enables long term, openhole, hydraulic isolation while having the ability to allow for expansion and/or contraction due to thermal effects and maintain an effective sealing and anchoring system. The zonal isolation system 80 also retains the differential pressure rating for wider open hole internal diameters or changes in the open hole internal diameter within the specified operating envelope. After deployment, the system uses the differential pressure to maintain energized seals and once the well is put into production or injection, the differential of the pressure created may re-energize the seal.
To enable setting of the zonal isolation tool 29 discussed above, the upper polished bore receptacle 86 may be placed above the zonal isolation tool and a lower polished bore receptacle 88 may be placed below the zonal isolation tool, as shown in FIGS. 16 and 21. The upper polished bore receptacle 86 may comprise a tubular structure 96 having a first end 98 and a second end 100. The first end 98 and the second end 100 of the upper polished bore receptacle 86 may be threaded, preferably using premium threads. The upper polished bore receptacle 86 may have a continuous inner diameter 102 which is smooth and polished. The packing of the setting tool 28 will be positioned within the inner diameter 102 during setting. Similarly, the lower polished bore receptacle 88 may comprise a tubular structure 104 having a first end 106 and a second end 108. The lower polished bore receptacle 88 may also include a continuous inner diameter 110 which is smooth, however, a locating profile 112 machined as a feature in the inner diameter 110 of the lower polished bore receptacle 88 may be included to assist in locating the setting tool 28 within the inner diameter of the lower polished bore receptacle. The locating profile 112 is a pattern of grooves 114 for engaging and seating fingers 116 of a locating collet 118. The engagement of the locating profile 112 and the fingers 116 provide an interference interaction between the components so that in order for the locating profile and the fingers to be disengaged, a specific amount of tensional force must be applied to the work string. This provides indication at the surface of the well that the zonal isolation tool has reached its intended position downhole. The locating profile is especially beneficial in long, horizontal, openhole completions. It is understood that the zonal isolation system may include more than two polished bore receptacles or one polished bore receptacle with a communication port that is attached to the zonal isolation tool.
The zonal isolation system 80 may also include a pair of anchors for preventing movement of the zonal isolation tool 29 relative to the openhole by gripping the borehole wall, as shown in FIG. 16. To prevent transmission of additional loads and movements into adjacent tubulars, a piston effect resulting from a fully expanded zonal isolation tool may be isolated using the pair of anchors. The pair of anchors comprises a first anchor 82 and a second anchor 84 which are located generally adjacent to the zonal isolation tool 29. The first anchor 82 may be placed above the zonal isolation tool and the second anchor 84 may be placed below the zonal isolation tool. The anchors 82, 84 are located in between the zonal isolation tool 29 and the polished bore receptacles 86, 88 and may be activated by using the setting tool 28 used for setting the zonal isolation tool either simultaneously or in the same trip. The anchors may be attached to the polished bore receptacles via threads. It is understood that the zonal isolation system may be deployed having only one anchor, multiple anchors, or in some cases no anchor will be used.
The first anchor 82 and the second anchor 84 support tensile and compressive forces on the tubular string, and provide a torsional load path. The effectiveness of the anchors may be a function of the friction coefficient of the openhole and the radial load applied against the formation. The coefficient of friction is related to the type of formation and fluids present downhole in the region of setting the zonal isolation system. In order to protect the formation from fracture, it is important that the radial loads remain below the fracture pressure of the formation. Therefore, the load should be distributed over a large surface area.
The anchors used with the zonal isolation system may be of several types. For example, as illustrated in FIG. 17, a classical slip type anchor 120 may be used. The classical slip anchor 120 comprises a cone that pushes slips outward toward the openhole wall until the slips make contact with the openhole wall. Friction against the formation maintains the anchor in position. To initiate contact with the formation, a hydraulic piston may be used, and a ratchet maintains the anchor in position and prevents the anchor from relaxing or moving.
A two-stage slip anchor 122 may also be used and contains a pair of support slips on the extremities, or ends of the anchor, and a pair of principal slips in a center of the anchor, as shown in FIG. 18. The pair of support slips is based on a C-ring design, and the pair of principal slips are based on a barrel slip design. Contact is initiated in the same manner as in the classical slip anchor discussed above.
In the alternative, a self-locking anchor 124 may be used, as illustrated in FIG. 19. The self-locking anchor 124 realizes increased friction and contact pressure with the formation as the axial forces are increased. The self-locking anchor may comprise a collet-slip design having blades similar to collet fingers, and machined teeth similar to a barrel slip. The collet fingers may be compressed until the collet fingers expand outward and contact the formation wall. The internal part of the self-locking anchor maintains the outward force against the openhole, thus providing the anchor.
It is understood that a penetrator-type anchor system 126 shown in FIG. 20 may be used and consists of arms, or spikes, that extend outward and bury/anchor into the formation. It is also understood that other types of anchors may be used with the zonal isolation system.
Referring to FIGS. 16 and 21, the zonal isolation system 80 may also include the expansion joint 90 (also called a compaction joint) to allow for movement due to external forces caused by temperature fluctuations downhole. The expansion joint 90 also allows for the movement of components of the zonal isolation system and tubulars that may be adjacent to the zonal isolation system. The expansion joint 90 may be attached to the polished bore receptacle using a threaded connection.
The tubulars attached to the zonal isolation system may expand and contract due to thermal changes. The expansion joint 90 allows for contraction and expansion of that tubular basepipe. The expansion joint 90 is capable of supporting the weight of the tubular string by allowing for changes in length but still maintaining pressure integrity from its inner diameter to its outer diameter. The expansion joint may be inactive (locked) during installation and then activated (unlocked) during the setting and operation stages.
Referring to FIG. 16, the setting string 92 may be used in conjunction with the setting tool 28 discussed above to deploy the zonal isolation tool 29. The setting string 92 may be installed within the zonal isolation system for activating one or more of the components above in the zonal isolation system. The setting string 92 includes sealing elements that are positioned at the time of setting in the pair of polished bore receptacles above and below the zonal isolation tool. By positioning the setting string in this manner, a pressure chamber is formed that communicates with the zonal isolation tool allowing for activation of the zonal isolation tool and/or the pair of anchors.
The setting string 92 may set all of the components in a single trip simultaneously or one device at a time. The setting string 92 has several features to assist in the setting of the described components. The collet 118 may be attached to the setting string 92 which mates with the polished bore receptacle which includes the locating profile 112 discussed above. The setting string 92 may also comprise ports, checks, or valves to facilitate wash-down or debris removal capabilities while running in the borehole (not shown). These features assist operators specifically in long, horizontal, openhole completions. It is understood that the setting string may also comprise devices to set other completion equipment during the same single trip, such as production packers, sump packers, and formation isolation valves.
Referring to FIG. 16, the internal tubing string used to transport production or injection fluids is the isolation string 94. The isolation string 94 may be installed after setting the zonal isolation system to maintain separation of zones during production or injection. The isolation string 94 utilizes the polished bore receptacles to complete the zonal isolation within the tubing string. The isolation string 94 may include a seal which may interact with the polished bore receptacles to effectively isolate the desired zone. It is understood that the type of seal used may be bonded seals, chevron seals or any seal which effectively seals the zones. Additionally, the setting string may include seals which seal on the inside of the polished bore receptacle to separate the zones.
The isolation string 94 maintains pressure integrity along its length, and provides the remaining separation for zonal isolation. The isolation string may be installed in place of the setting string after all of the components have been activated and are operational. The isolation string 94 may include a packing stack to seal in the lower polished bore receptacle which is located downhole, and may also include a locating collet to mate with the locating profile 112 on the lower polished bore receptacle.
It is understood that the zonal isolation tools as described and claimed herein may connect in any number of ways to their wellbore counterparts. Each end of the zonal isolation system may be adapted to be attached in a tubular string. This can be through threaded connections, friction fits, expandable sealing means, and the like, all in a manner well known in the oil tool arts. Although the term tubular string is used, this can include jointed or coiled tubing, casing or any other equivalent structure for positioning tools as disclosed herein. The materials used can be suitable for use with production fluid or with an inflation fluid.
The embodiments described herein may be used in an open hole for sandface completions utilizing stand-alone screens. However, the embodiments described herein may also be adapted for use in open-hole gravel pack sand control applications. In the latter role, the embodiments described herein may incorporate the use of alternate path transport and shunt tubes to assist gravel slurry placement. Additionally, the embodiments described herein may be used in sand control applications utilizing expandable screens. Aside from the various sand control applications listed, the embodiments described herein may also be used as an annular barrier, or for compartmentalizing long open-hole sections.
Although only a few exemplary embodiments of this invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the spirit of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims.